1. Field of the Invention
The invention relates generally to drilling boreholes through subsurface formations. More particularly, the invention relates to a method and a system for controlling the rate of release of a drill string to maintain equivalent density at a selected value during drilling.
2. Background Art
Drilling wells in subsurface formations for oil and gas wells is expensive and time consuming. Formations containing oil and gas are typically located thousands of feet below the earth surface. Therefore, thousands of feet of rock and other geological formations must be drilled through in order to establish production. While many operations are required to drill and complete a well, perhaps the most important is the actual drilling of the borehole. The cost associated with drilling a well is primarily time dependent. Accordingly, the faster the desired penetration depth is achieved, the lower the cost for drilling the well. However, cost and time associated with well construction can increase substantially if wellbore instability problems or obstacles are encountered during drilling. Therefore, successful drilling requires achieving a penetration depth as fast as possible but within the safety limits defined for drilling operation.
Achieving a penetration depth as fast as possible during drilling requires drilling at an optimum rate of penetration. The rate of penetration achieved during drilling depends on many factors, however, the primary factor is the axial force (weight) on bit. As disclosed in U.S. Pat. No. 4,535,972 to Millheim, et al., rate of penetration generally increases with increasing weight on bit until a certain weight on bit is reached and then decreases with further weight on bit. Thus, there is generally a particular weight on bit that will achieve a maximum rate of penetration.
However, the rate of penetration of a bit also depends on many factors in addition to the weight on bit. For example, the rate of penetration depends upon characteristics of the formation being drilled, the speed of rotation of the drill bit, and the rate of flow of the drilling fluid. Because of the complex nature of drilling, a weight on bit that is optimum for one set of conditions may not be optimum for another set of conditions.
One conventional method used to determine an optimum rate of penetration for a particular set of drilling conditions is known as a “drill off test,” which is disclosed, for example, in U.S. Pat. No. 4,886,129 to Bourdon. During a drill off test, a drill string supported by a drilling rig is lowered into the borehole. When the bit contacts the bottom of the borehole, drill string weight is transferred from the rig to the bit until an amount of weight greater than the expected optimum weight on bit is applied to the bit. Then, while holding the drill string against vertical motion at the surface, the drill bit is rotated at the desired rotation rate with the fluid pumps at the desired pressure. As the bit is rotated, it cuts through the earth formation. Because the drill string is held against vertical motion at the surface, weight is increasingly transferred from the bit to the rig as the bit cuts through the earth formation. As disclosed in U.S. Pat. No. 2,688,871 to Lubinsky, by applying Hooke's law, an instantaneous rate of penetration may be calculated from the instantaneous rate of change of weight on bit. By comparing bit rate of penetration with respect to weight on bit during the drill off test, an optimum weight on bit can be determined. In typical drilling operations, once an optimum weight on bit is determined, a driller (rig operator) attempts to maintain the weight on bit at that optimum value during drilling.
A limitation of using an optimum weight on bit determined from a drill off test is that the weight on bit value thus determined is optimum only for the particular set of conditions experienced during the test, such as drilling fluid (“mud”) flow rate, the type of formation being drilled, temperature and pressure conditions, etc. Drilling conditions are dynamic, and during the course of drilling will change, sometimes without warning. As a result, the weight on bit determined in the drill off test may no longer be optimum. Therefore, to achieve an optimum completion time for a well, the model used to determine the weight on bit corresponding to an optimum rate of penetration should be substantially continuously updated to match current drilling conditions as conditions in the well change during drilling.
In addition to achieving the fastest rate of penetration for weight on bit, successful drilling also requires drilling within the safety limits set for drilling operations to avoid costly, time-consuming problems that can be encountered during drilling. Problems that may be encountered during drilling operations include events such as sticking (or stuck pipe), kick, loss of circulation (or formation fracture), and washout. Sticking occurs when the drill string gets stuck in the wellbore, such as due to the build-up of cuttings in the wellbore due to inefficient clean out or collapse of the wellbore. Kick is any unexpected entry of formation fluid into the borehole. A kick may be detected, for example, by an excess in the flow rate of the returning fluid from the wellbore over the rate at which the drilling fluid is pumped into the wellbore. Loss of circulation is a loss of drilling fluid typically due to the presence or opening of a fractures in the formations exposed to the borehole. The loss of drilling fluid to the formations can be detected, for example, by a loss of the fluid flow rate returned to the surface through the wellbore annulus. Washout is excessive enlargement of the wellbore caused by solvent and erosion action by drilling fluid. Washout can cause severe damage to the formation, contamination of the connate formation fluids, and can waste costly drilling mud.
Recently, it has been shown that closely monitoring borehole fluid pressures (also referred to as “annular pressures”), especially near the bottom of the wellbore, during drilling can aid in the diagnosis of the condition of the wellbore and help avoid potential dangerous well control events during drilling operations. Annular pressure measurements during drilling, when used in conjunction with measuring and controlling other drilling parameters, have been shown to be particularly helpful in the early detection of events such as sticking, hanging, or balling stabilizers, mud problem detection, detection of cuttings build-up, improved steering performance.
During drilling operations, it is important to maintain the annular pressure of the drilling fluid within a range determined by the pressure limits for wellbore stability. Typically, the lower pressure limit for wellbore stability is the greater of the fluid pressure in the drilled formations, or the amount of pressure needed to avoid wellbore collapse. The upper pressure limit for wellbore stability is typically the lowest fracture pressure of the drilled formations exposed to the wellbore. When drilling fluid pressure exceeds the formation fracture pressure, there is a risk of creating or opening fractures, resulting in loss of drilling fluid circulation and damage to the affected formation. As is known in the art, fracture pressures of formations can be determined from overburden pressure and lateral stresses in the particular formations, and from mechanical properties of the particular formations.
Because the hydrostatic pressure of drilling fluid in the annulus of the borehole is a function of vertical depth and because movement of the mud induces frictional pressure drop, the annular pressure at a given depth is often converted to an equivalent density, referred to as an “equivalent circulating density” (ECD). Equivalent circulating density is considered a very useful representation of pressure in the annulus of the wellbore during drilling because it reflects both the hydrostatic and dynamic components of annular pressure and, once determined at one position, can be used to accurately predict annular pressure at any position in the wellbore. During drilling, the equivalent circulating density exceeds the static density of the fluid. The equivalent circulating density is caused by pressure losses in the annulus between the drilling assembly and the wellbore and is strongly dependent on the annular geometry and mud hydraulic properties. The maximum equivalent circulating density is normally at the drill bit, and pressures of more than 100 psi above the static mud weight may occur in long, extended reach and horizontal wells.
In many high pressure, high temperature (HPHT), deepwater, and extended reach wells, the margin between the formation pore pressure or formation collapse pressure, and the formation fracture pressure can diminish to the point that maintaining the equivalent circulating density within a narrow range can become critical to the success of the wellbore.
Measuring annular pressure while drilling has also been found to be useful in the early identification of drilling problems such as the inefficient removal of drill cuttings from the hole (“hole cleaning”). Increasing equivalent density of the drilling fluid caused by inefficient removal of drill cuttings and can help the driller avoid formation breakdown resulting from high pressure surges, or problems such as stuck drill pipe caused by packing off of the wellbore annulus with drill cuttings.
Equivalent circulating density may be calculated using hydraulics models from input well geometry, mud density, mud rheology, and flow properties, through each component of the circulating system. However, there are often large discrepancies between the measured and calculated pressures due to uncertainties in the calculations, poor knowledge of pressure losses through certain components of the circulation system, changes in the mud density and rheology with temperature and pressure, and/or poor application of hydraulics models for different mud systems. A more accurate reflection of equivalent circulating density may also be obtained from pressure data collected during drilling.
Leak-off tests (LOTs) and formation integrity tests (FITs) are very useful in determining limits that enable efficient management of the equivalent density of the drilling fluid within the safe pressure window. Using these tests, drilling engineers, or the like, can determine limits associated with drilling environment parameters, such as equivalent density.
As disclosed in C. D. Ward et al., Pressure While Drilling Data Improves Reservoir Drilling Performance, paper no. 37588, Society of Petroleum Engineers, Richardson, Tex., (1997), for drilling success in high angle wells, it is critical to maintain the equivalent circulating density (ECD) within safe operating limits defined by the formation fluid, collapse, and facture pressures. Operating outside these limits can lead to expensive lost circulation, differential sticking, and packing-off incidents. Monitoring the actual down-hole annulus pressure in real-time, such as with a pressure while drilling (“PWD”) tool, rather than relying on inferred pressures from predictive models, has allowed borehole operators to better maintain ECD within the operating limits dictated by the formation being drilled.
In recent years, drilling operators have increasingly taken to monitoring downhole pressures using PWD instruments in an attempt to operate drilling rigs so as to maintain annular downhole pressures within the desired limits defined for the wellbore. Typically, such drilling rig operation includes having the rig operator (driller) manually control release of the drill string so as to keep the ECD (determined from the annular pressure measurements) within a selected range. How the driller controls the release of the drill string is somewhat unpredictable, and is related to the level of attention the driller has to give to a number of different tasks. Therefore, to achieve an optimum rate of penetration during drilling while avoiding undesired events during drilling, a method and a system are desired for automatically controlling drilling to achieve an optimum rate of penetration which takes into account safety limits defined for the drilling environment.